Wells, also known as wellbores or boreholes, are drilled to reach underground petroleum and other subterranean hydrocarbons. While or after a well is being drilled, a great quantity of information relating to parameters and conditions downhole is desirable. Such information typically includes characteristics of the earth formations traversed by the wellbore, in addition to data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole, which commonly is referred to as "logging," can be performed by several methods. In conventional oil well wireline logging, a probe or "sonde" is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The sonde may include one or more sensors to measure parameters downhole and typically is constructed as a hermetically sealed cylinder for housing the sensors, which hangs at the end of a long cable or "wireline." The cable or wireline provides mechanical support to the sonde and also provides an electrical connection between the sensors and associated instrumentation within the sonde, and electrical equipment located at the surface of the well. Normally, the cable supplies operating power to the sonde and is used as an electrical conductor to transmit information signals from the sonde to the surface. In accordance with conventional techniques, various parameters of the earth's formations are measured and correlated with the position of the sonde in the borehole, as the sonde is pulled uphole.
While wireline logging is useful in assimilating information relating to formations downhole, it nonetheless has certain disadvantages. For example, before the wireline logging tool can be run in the wellbore, the drillstring and bottomhole assembly must first be removed or tripped from the borehole, resulting in considerable cost and loss of drilling time for the driller (who typically is paying daily fees for the rental of drilling equipment). In addition, because wireline tools are unable to collect data during the actual drilling operation, drillers must at times make decisions (such as the direction to drill, etc.) possibly without sufficient information, or else incur the cost of tripping the drillstring to run a logging tool to gather more information relating to conditions downhole. In addition, because wireline logging occurs a relatively long period after the wellbore is drilled, the accuracy of the wireline measurement can be questionable. As one skilled in the art will understand, the wellbore conditions tend to degrade as drilling fluids invade the formation in the vicinity of the wellbore. In addition, the borehole shape may begin to degrade, reducing the accuracy of the measurements.
Because of these limitations associated with wireline logging, there was an emphasis on developing tools that could collect data during the drilling process itself. By collecting and processing data during the drilling process, without the necessity of tripping the drilling assembly to insert a wireline logging tool, the driller can make accurate modifications or corrections "real-time", as necessary, to optimize drilling performance. With a steerable system the driller may change the direction in which the drill bit is headed. By detecting the adjacent bed boundaries, adjustments can be made to keep the drill bit in an oil rich layer or region. Moreover, the measurement of formation parameters during drilling, and hopefully before invasion of the formation, increases the usefulness of the measured data. Further, making formation and borehole measurements during drilling can save the additional rig time which otherwise would be required to run a wireline logging tool.
Designs for measuring conditions downhole and the movement and location of the drilling assembly, contemporaneously with the drilling of the well, have come to be known as "measurement-while-drilling" techniques, or "MWD." Similar techniques, concentrating more on the measurement of formation parameters of the type associated with wireline tools, commonly have been referred to as "logging while drilling" techniques, or "LWD." While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For the purposes of this disclosure, the term MWD will be used with the understanding that the term encompasses both the collection of formation parameters and the collection of information relating to the position of the drilling assembly while the bottomhole assembly is in the well.
The measurement of formation properties during drilling of the well by MWD systems improves the timeliness of measurement data and, consequently, increases the efficiency of drilling operations. Typically, MWD measurements are used to provide information regarding the particular formation through which the borehole crosses. Currently, logging sensors or tools that commonly are used as part of either a wireline or an MWD system include resistivity tools. Resistivity tools are effective because for a formation to contain petroleum, and for the formation to permit the petroleum to flow through it, the rock comprising the formation must have certain well known physical characteristics. One characteristic is that the formation has a certain measurable resistivity (the inverse of conductivity), which can be determined by providing an electromagnetic wave of a particular frequency through the formation. As will be apparent to one skilled in the art, the propagating wave suffers both attenuation and phase shift as it travels through the formation. Analysis of this attenuation and phase shift provides the resistivity of the formation surrounding the resistivity tool.
Ordinarily, a well is drilled vertically for at least a portion of its final depth. The layers or strata that make up the earth's crust are generally substantially horizontal. Therefore, during vertical drilling, the well is substantially perpendicular to the geological formations through which it passes. In certain applications, however, such as when drilling from an off-shore platform, or when drilling through formations in which the reservoir boundaries extend horizontally, it is desirable to drill wells that are oriented more horizontally. When drilling horizontally, it is desirable to maintain the well bore in the pay zone (the formation which contains hydrocarbons) as much as possible so as to maximize the recovery. This can be difficult since formations may dip or divert. Thus, while attempting to drill and maintain the well bore within a particular formation, the drill bit may approach a bed boundary. Many in the industry have noted the desirability of an MWD system that could be especially used to detect bed boundaries and to provide real-time data to the driller to enable the driller to make directional corrections to stay in the pay zone. Alternatively, the MWD system could be used as part of a "Smart" system to automatically maintain the drill bit in the pay zone. See, e.g. commonly assigned U.S. Pat. No. 5,332,048, the teachings of which are incorporated by reference herein. The assignee has also developed a system that permits the measurement of MWD data at the drill bit to provide an earlier indication of bed boundaries and formation characteristics. See U.S. Pat. No. 5,160,925. The use of an MWD system with these other systems makes it possible to conduct at least certain portions of drilling automatically.
The various "beds" or layers in the earth have characteristic resistivities which can be used to identify their position. For example, in a so-called "shaley-sand" formation, the shale bed can have a low resistivity of about 1 ohm per meter. A bed of oil-saturated sandstone, on the other hand, is likely to have a higher resistivity of about 10 ohms per meter, or more. The sudden change in resistivity at the boundary between beds of shale and sandstone can be used to locate these boundaries. In horizontal drilling, the drill bit preferably can then be steered to avoid this boundary and keep the wellbore inside the oil-producing bed. However, to accomplish this detection reliably, a great deal of data is required from the resistivity tool.
Resistivity tools have undergone a substantial evolution in order to obtain more resistivity data. FIG. 2 shows an early resistivity tool 220 as part of a bottomhole assembly. A well bore 200 is drilled through formation 205, and contains a drill string 210. Attached to drill string 210 is drill bit 215. A first receiver 230 is as close as practical to the drill bit 215, while a second receiver 240 and a single transmitter 250 are located further up the drill string. Transmitter 250 generates an electromagnetic (EM) wave 255 at a selected frequency that flows toward receivers 230, 240 via the formation 205. EM wave 255 is measured at receivers 230 and 240. First and second signals result.
The exact frequency selected for the EM wave depends on certain criteria. On the one hand, as the transmitter 250 is placed further away from the receiver pair 230, 240, signal attenuation becomes more severe. To compensate, the transmitter may use more power to generate a stronger signal that can be detected by the receiver pair. But because lower frequency signals attenuate more slowly than do high frequency signals, use of lower frequency signals can reduce or eliminate this need. On the other hand, as the transmitter is placed closer to the receiver pair, phase shift and attenuation become harder to detect. A higher frequency makes this detection easier. Thus, lower frequency signals tend to be preferred as the distance between the transmitter and receiver pair increases, and higher frequency signals tend to be preferred as the distance decreases between the transmitter and the receiver pair.
First and second signals result from receivers 230 and 240, respectively. The difference between the first and second signals can be used to establish the attenuation and phase shift of EM wave 255. Combined with the known distance between the receivers, this yields the resistivity of the formation 205.
Improvements to this design to yield more data have been made. For example, FIG. 3 shows a resistivity tool 300 with three transmitters in addition to a pair of receivers. This tool 300 includes receivers R1310 and R2320 in addition to transmitters T1330, T2340, and T3350. The addition of two transmitters provides more resistivity data During operation, a single transmitter fires, such as transmitter T1, sending EM wave at a particular frequency into the formation. The wave is then received at receivers R1310 and R2320 and an attenuation and phase shift can be determined. Transmitter T2 then fires at the same frequency, followed by transmitter T3. Each firing results in readings at the two receivers 310 and 320. Multiple readings at the receivers 310 and 320 result in multiple measurements of phase shift and attenuation of the signals. Consequently, a more accurate resistivity profile can be obtained.
FIG. 4 shows a resistivity tool 400 with four transmitters 430, 440, 450, 460 in addition to a pair of receivers 410, 420. As with the resistivity tool shown in FIG. 3, each transmitter fires sequentially, with difference readings being taken between the waveforms detected at the receiver pair. Because transmitter 460 is located further away from the pair of receivers 410, 420, it has been found advantageous to fire this transmitter 460 at a lower frequency than the other transmitters 430, 440, 450. A lower frequency waveform from the transmitter reads deeper than a comparable higher frequency waveform, but results in lower vertical resolution. This lower resolution can be a problem, for example, when attempting to recognize the presence of a thin bed. Thus, it is advantageous in this design to utilize two different frequencies for the set of four transmitters. Moreover, the smaller the distance between a transmitter and a pair of receivers, the less the depth of investigation into the formation. Thus, the addition of a fourth transmitter results in more data being received at the receivers, and a more accurate profile of resistivity around the well bore.
However, the addition of more transmitters to a resistivity tool also leads to some significant drawbacks. In particular, modem resistivity tools are very slow. Each transmitter of these resistivity tools is fired sequentially, meaning that a greater number of transmitters results in a greater number of transmitter firings in any "set" of transmitter-receiver resistivity readings. Because firings occur sequentially, a large number of transmitters results in more time being necessary to complete a set of resistivity readings. In addition, each transmitter-receiver pair spacing corresponds to a different depth of investigation into the formation. With the transmitters being fired sequentially while the resistivity tool is being moved up or down the wellbore, more transmitters result in a greater distance along the borehole wall for identical depth of investigation measurements. Thus, a large number of transmitters slow down the maximum practical speed at which a resistivity tool can proceed past a borehole wall.
A less than ideal rate of movement up or down the borehole is not an insignificant problem. For example, in wireline logging, the sonde is pulled past the borehole wall as quickly as possible to minimize the time required to recover hydrocarbons and to minimize costs. As another example, in the MWD environment, a borehole may already be partially drilled and the drill bit assembly lowered a significant distance into the earth prior to actual drilling. An operator would like to quickly obtain a set of resistivity measurements while the drill string is being lowered downhole in the old wellbore. Further, in certain formations, it is the data acquisition rate of the MWD tools, and not the ability of the drill bit to cut through formation, that is a limiting factor on drilling speed Data acquisition while the drill bit assembly is being "tripped" or pulled up from the borehole is often also desirable. Because multiple transmitter resistivity tools use a long period of time to obtain a "set" of measurements, the disadvantages of a large number of transmitters undermine the advantages of a large number of transmitters.
Compensated resistivity tools have also been developed. The development of compensated resistivity tools was in response to the necessity for temperature characterization of uncompensated resistivity tools. Temperature characterization is necessary because of the range of temperatures a resistivity tool is exposed to as it progresses downhole. This temperature affects the response of the circuitry (e.g. resistors, capacitors) in the resistivity tool. Consequently, for accuracy each uncompensated resistivity tool must be calibrated across a range of temperatures. Further, to maintain accuracy at certain intervals this must be repeated for each tool. This process requires extra time, effort, and expense.
FIG. 5 shows a resistivity tool with compensation. Tool 500 includes a pair of receivers 510, 520 and four transmitters 530, 540, 550, 560. To increase the number of waveforms received at the receivers, and hence the amount of data, each transmitter is fired at two different frequencies. For example, in addition to a 2 MegaHertz (MHz) frequency, the transmitters of this design may fire at 400 kHz. This results in a deeper investigation into the surrounding formation. Unlike the tool shown in FIG. 4, it can be seen that the compensated tool includes a symmetric pair of transmitters placed ahead of the receivers. The transmitters ahead of the receivers are placed the same distance away from the receivers as the transmitters behind the receivers, and thus have the same depth of investigation into the formation. The results from corresponding pairs of transmitter, may be "averaged" as is known in the art, and the effects of electronic component response due to temperature variations greatly reduced.
FIG. 6 shows a resistivity tool with "pseudo-compensation." Tool 600 includes a pair of receivers and a set of transmitters. It can be seen that this design places only two transmitters ahead of the receiver pair, whereas there are three transmitters behind the receiver pair. The location of each transmitter ahead of the receiver pair may be determined because each transmitter is placed half way between where a pair of transmitters would be located were this a fully compensated resistivity tool. One advantage of this design is that the receivers are closer to the drill bit as compared to a fully compensated tool. At the same time, this design also achieves some level of compensation, although temperature characterization is still required to some extent. However, those in the industry are dubious whether the benefits in this design outweigh the error that is introduced by having an unbalanced configuration and the need to place the receivers further away from the drill bit than in an uncompensated design.
Although substantial improvements have been made to resistivity tool design, there still exist numerous problems. As explained, modem resistivity tools are slow and limit the maximum rate at which the tool may proceed past a wellbore wall. In addition, modern resistivity tools have high power requirements because of an increased number of transmitters and because transmitters far away from the receiver pair often tramsmit a stronger signal than transmitters close to the receiver pair. For conventional MWD tools, in particular, power is a very precious commodity and this is another significant drawback. Thus, a resistivity tool is desirable that would be capable of obtaining data regarding the formation near the drill bit in a shorter period of time. Ideally, it would collect nearly the same or a greater amount than conventional resistivity tools. It would also be ideal if this resistivity tool required less power than other known resistivity tools. If this tool also eliminated or reduced other problems, it would also be ideal.